2
- 1 **CHAPTER 2 ELECTRIC POWER SECTO**  **R PROFILE 2.1**  **Introduction** This chapter discusses important aspects of the power sector that relate to the final MATS Rule, including the types of power
- sector sources affected by the rule, and provides background on the power sector a nd electric generating units (EGUs). In addition, this chapter provides some historical background on EPA regulation of and future projections for the power sector. The specific impacts of MATS are discussed in Chapter 3. **2.2 Power Sector Overview**  The prod uction and delivery of electricity to customers consists of three distinct segments: generation, transmission, and distribution. **2.2.1 Generation**  Electricity generation is the first process in the delivery of electricity to consumers. Most of the existing capacity for generating electricity involves creating heat to rotate turbines which, in turn, create electricity. The power sector consists of over 17,000 generating units, comprising fossil
-fuel
-fired units, nuclear units, and hydroelectric and other rene wable sources dispersed throughout the country (see Table 2
- 1). **Table 2 -**  **1. Existing Electricity Generating Capacity by Energy Source, 2009** 

**Energy Source Number of Generators**  **Generator Nameplate Capacity (MW)**  **Generator Net Summer Capacity**  **(MW)** Coal 1,436 3 38,723 314,294 Petroleum 3,757 63,254 56,781 Natural Gas 5,470 459,803 401,272 Other Gases 98 2,218 1,932 Nuclear 104 106,618 101,004 Hydroelectric Conventional 4,005 77,910 78,518 Wind 620 34,683 34,296 Solar Thermal and Photovoltaic 110 640 619 W ood and Wood Derived Fuels 353 7,829 6,939 Geothermal 222 3,421 2,382 Other Biomass 1,502 5,007 4,317 Pumped Storage 151 20,538 22,160 Other 48 1,042 888 Total 17,876 1,121,686 1,025,402 Source: EIA ( 2009 ).2
- 2

These electric generating sources provide e lectricity for commercial, industrial, and residential uses, each of which consumes roughly a quarter to a third of the total electricity produced (see Table 2
- 2). Some of these uses are highly variable, such as heating and air conditioning in residential and commercial buildings, while others are relatively constant, such as industrial processes that operate 24 hours a day. **Table 2 -**  **2. Total U.S. Electric Power Industry Retail Sales in 2009 (Billion kWh)**  **Sales/Direct Use (Billion kWh) Share of Total End U**  **se**

**Retail Sales** Residential 1,364 37%

Commercial 1,307 35% Industrial 917 25% Transportation 8 0.2% **Direct Use** 127 3% **Total End Use 3,723**  100% Source: EIA ( 2009 ). In 2009, electric generating sources produced 3,950 billion kWh to meet electrici ty demand. Roughly 70 percent of this electricity was produced through the combustion of fossil fuels, primarily coal and natural gas, with coal accounting for the largest single share (see Table 2
- 3). **Table 2 -**  **3. Electricity Net Generation in 2009 (Billion**  **kWh) Net Generation (Billion kWh)**  **Fuel Source Share** Coal 1,756 44.5% Petroleum 39 1.0% Natural Gas 921 23.3% Other Gases 11 0.3% Nuclear 799 20.2% Hydroelectric 273 6.9% Other 151 3.8% **Total 3,950**  **100%** Source: EIA ( 2009 ). Note: Retail sales are not equal to net generation because net generation includes net exported electricity and loss of electricity that occurs through transmission and distribution.2
- 3

Coal
-fired generating units typically supply “ base
- load ” electricity, the portion of electricity loads which are continually present, and typically operate throughout the day. Along with nuclear generation, these coal units meet the part of demand that is relatively constant. Although much of the coal fleet operates as base load, there can be notable differences across various facilities (see Table 2
-4). For example, coal
-fired units less than 100 MW in size compose 37 percent of the total number of coal
-fired units, but only 6 percent of total coal
-fired capacity. Gas
-fired generation is better able to vary output and is the primary option used to meet the variable portion of the electricity load and typically supplies “ peak” power, when there is increased demand for electricity (for example, when businesses operate throughout the day or when people r eturn home from work and run appliances and heating/air

conditioning), versus late at night or very early in the morning, when demand for electricity is reduced. However, the evolving economics of the power sector, in particular the increased natural gas s upply and relatively low natural gas prices, have resulted in more gas being utilized as base load energy. Figure 2
- 1 shows the distribution and relative size of the fossil
-fuel fired generating capacity across the United States. **Table 2 -** **4. Coal Steam Elec** **tricity Generating Units, by Size, Age, Capacity, and Efficiency**

**(Heat Rate)**

**Unit Size Grouping (MW)**  **No. Units % of All**  **Units Avg. Age**  **Avg. Net Summer**  **Capacity (MW)**  **Total Net**

**Summer Capacity**  **(MW) % Total** 

**Capacity Avg. Heat** 

**Rate (Btu/kWh)**  0 to 25 193 15% 4 5 15 2,849 1% 11,154 >25 to 49 108 9% 42 38 4,081 1% 11,722 50 to 99 162 13% 47 75 12,132 4% 11,328 100 to 149 269 21% 49 141 38,051 12% 10,641 150 to 249 81 6% 43 224 18,184 6% 10,303 250 and up 453 36% 34 532 241,184 76% 10,193 **Total 1,266**  **316, 480**  Source: National Electric Energy Data System (NEEDS) v.4.10 Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed to a generation
-weighted or capacity
-weighted average heat rate.) A lower he at rate indicates a higher level of fuel efficiency. Table is limited to coal
- steam units online in 2010 or earlier, and excludes those units with planned retirements.2
-4

**Figure 2** **- 1.**  **Fossil Fuel -**  **Fired Electricity Generating Facilities, by Size** Source: Natio nal Electric Energy Data System (NEEDS) 4.10 Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on
- line by the end of 2011. This includes planned new builds and planned retirements. In areas with a dense conce ntration of facilities, some facilities may be obscured. **2.2.2 Transmission**  Transmission is the term used to describe the movement of electricity over a network of high voltage lines, from electric generators to substations where power is stepped down for local distribution. In the US and Canada, there are three separate interconnected networks of high voltage transmission lines , 1 each operating at a common frequency. Within each of these transmission networks, there are multiple areas where the operation o f power plants is monitored and controlled to ensure that electricity generation and load are kept in balance. In some areas, the operation of the transmission system is under the control of a single regional operator; in others, individual utilities coord inate the operations of their generation, transmission, and distribution systems to balance their common generation and load needs.

1 These three network interconnections are the western US and Canada, corresponding approximately to the area west of the Ro cky Mountains; eastern US and Canada, not including most of Texas; and a third network operating in most of Texas. These are commonly referred to as the Western Interconnect Region, Eastern Interconnect Region, and ERCOT, respectively.2
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**2.2.3 Distribution**  Distribution of electricity involves networks of lower voltage lines and substations that take the higher voltage power from the transmission system and step it down to lower voltage levels to match the needs of customers. The transmission and distribution system is the classic example of a natural monopoly, in part because it is not practical to have more th an one set of lines running from the electricity generating sources to substations or from substations to residences and business. Transmission has generally been developed by the larger vertically integrated utilities that typically operate generation and distribution networks. Distribution is handled by a large number of utilities that often purchase and sell electricity, but do not generate it. Over the last couple of decades, several jurisdictions in the United States began restructuring the power industry to separate transmission and distribution from generation, ownership, and operation. As discussed below, electricity restructuring has focused primarily on efforts to reorganize the industry to encourage competition in the generation segment of the ind ustry, including ensuring open access of generation to the transmission and distribution services needed to deliver power to consumers. In many states, such efforts have also included separating generation assets from transmission and distribution assets t o form distinct economic entities. Transmission and distribution remain price
- regulated throughout the country based on the cost of service. **2.3 Deregulation and Restructuring**  The process of restructuring and deregulation of wholesale and retail electric m arkets has changed the structure of the electric power industry. In addition to reorganizing asset management between companies, restructuring sought a functional unbundling of the generation, transmission, distribution, and ancillary services the power se ctor has historically provided, with the aim of enhancing competition in the generation segment of the industry. Beginning in the 1970s, government policy shifted against traditional regulatory approaches and in favor of deregulation for many important ind ustries, including transportation (notably commercial airlines), communications, and energy, which were all thought to be natural monopolies (prior to 1970) that warranted governmental control of pricing. However, deregulation efforts in the power sector w ere most active during the 1990s. Some of the primary drivers for deregulation of electric power included the desire for more efficient investment choices, the economic incentive to provide least
- cost electric rates through market competition, reduced cost s of combustion turbine technology that opened the door for2
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more companies to sell power with smaller investments, and complexity of monitoring utilities ’ cost of service and establishing cost
- based rates for various customer classes. The pace of restructu ring in the electric power industry slowed significantly in response to market volatility in California and financial turmoil associated with bankruptcy filings of key energy companies. By the end of 2001, restructuring had either been delayed or suspended in eight states that previously enacted legislation or issued regulatory orders for its implementation (shown as “Suspended ” in Figure 2
- 2 below). Another 18 other states that had seriously explored the possibility of deregulation in 2000 reported no legi slative or regulatory activity in 2001 (EIA, 2003 ) ( “ Not Active ” in Figure 2
- 2 below). Currently, there are 15 states where price deregulation of generation (restructuring) has occurred ( “Active ” in Figure 2
- 2 below). Power sector restructuring is more or less at a standstill; there have been no recent proposals to the Federal Energy Regulatory Commission (FERC) for actions aimed at wider restructuring, and no additional states have recently begun retail deregulation activity.

**Figure 2 -**  **2. Status of State Electricity Industry Restructuring Activities**  Source: EIA ( 2010b )
. **2.4 Emissions of Mercury and Other Hazardous Air Pollutants from Electric Utilities**  The burning of fossil fuels, which generates about 70 percent of our electricity nationw ide, results in air emissions of Hazardous Air Pollutants (HAPs): mercury, acid gasses, and non
- mercury metallic particulates. Additionally, SO 2 and NO x emissions from the power2
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sector are important precursors in the formation of fine particles and ozone ( NO x only). The power sector is a major contributor of all of these pollutants. The Emissions Overview Memorandum Technical Support Document (TSD) to the proposed air toxics standards (Docket number EPA
- HQ
- OAR
- 2009
- 0234) details the emissions of mercury and other HAPs emitted by EGUs. In 2005, EGU emissions of mercury accounted for approximately half of all anthropogenic mercury emissions in the U.S. Table 2
- 5 shows the trend in EGU and total anthropogenic mercury emissions from 1990
–2 005 and EGU mercury emi ssions reported in the Utility MACT Information Collection Request (ICR) in 2010. **Table 2 -**  **5. U.S. Anthropogenic Mercury Emissions, 1990** **– 2**  **010 1990**  **(tons) 1999** 

**(tons) 2005** 

**(tons) 2010**  **a**

**(tons)** EGU Hg Emissions 59 49 53 29 Non
- EGU Hg Emission 205 66 52 Not Available b **Total U.S. Hg Emissions 264**  **115 105**  **Not Available b** 

a The estimate of the current level of Hg emissions based on the 2010 ICR database may underestimate total EGU Hg emissions due to targeting of the 2010 ICR on the best performing EGUs. b Info rmation on recent U.S. EGU emissions was obtained using an ICR for EGUs only. This same information is not available for other sources, which were not covered by the ICR. In 2005, EGUs contributed 82 percent of U.S. hydrogen chloride emissions. Table 2
- 6 s hows the total HCl emissions from EGU and non
- EGU sources in 2005 and the EGU HCl emissions reported in the Utility MACT ICR in 2010. **Table 2 -**  **6. U.S. Hydrogen Chloride Emissions, 2005 and 2010**  **2005 a**  **(tons) 2010**  **b (tons)**  EGU HCl Emissions 350,000 106,000 Non
- EGU HCl Emissions 78,000 Not Available c **Total U.S. HCl Emissions 428,000**  **Not Available c** 

a 2005 emissions from the National Air Toxics Assessment Inventory. Available online at http://www.epa.gov/ttn /atw/nata2005/ . EGU emissions were extracted from the total using the MACT code field (1808). b The estimate of the current level of Hg emissions based on 2010 may underestimate the total EGU emissions due to targeting of the 2010 ICR on the best performi ng EGUs. c Information on recent U.S. EGU emissions was obtained using an ICR for EGUs only. This same information is not available for other sources, which were not covered by the ICR.2
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Individual fossil fuel
-fired units vary widely in their air emissions levels for HAPs, particularly when uncontrolled. In 2010, as reported in the Utility MACT ICR, mercury emissions range from less than 0.3 lb/trillion Btu (TBtu) to more than 20 lbs/TBtu. HCl emissions from coal
-fired units range from less than 0.00002 lb/m illion Btu (mmBtu) (for a unit with a scrubber) to over 0.1 lb/mmBtu. Additionally, emissions of fine particulates less than or equal to 2.5 microns (PM 2.5 ) range from 0.002 lb/mmBtu to over 0.06 lb/mmBtu. For an uncontrolled plant, mercury, acid gas, and particulate emissions are directly related to the elemental profile and ash content of the coal burned. Oil
-fired units also have a wide range of HAP emissions. Based on the Utility MACT ICR, Mercury emissions range from less than 0.01 lb/TBtu to more than 60 lbs/TBtu. HCl emissions from oil
-fired units range from less than 0.00001 lb/mmBtu (for a unit with a scrubber) to over 0.003 lb/mmBtu. Emissions of PM 2.5 range from less than 0.004 lb/mmBtu to over 0.07 lb/mmBtu. **2.5 Pollution Control Technologies**  Aci d gas HAPs (e.g., hydrogen chloride (HCl), hydrogen fluoride (HF), sulfur dioxide (SO 2 )) from coal
-fired power plants can be controlled by fuel selection, fuel blending, or post combustion controls. Fossil fuels, particularly coal, vary widely in the conte nt of pollutants like chlorine (Cl), fluorine (F), sulfur (S) and other HAPs, making fuel blending and/or switching an effective method for reducing emissions of HAPs. In general, it is easier to switch fuels within a coal rank (rather than across a coal r ank) due to similar heat contents and other characteristics. Switching fuels across ranks tends to trigger more costly modifications. As a compromise, blending is employed when a complete fuel switch adversely affects the unit. EGUs may also choose to retrofit post combustion controls to achieve superior pollutant removal. Post
combustion controls typically remove larger proportions of HCl and HF than SO 2 due to differences in molecular weight. Acid gas emissions (including SO 2 ) can be reduced with flue gas desulfurization (FGD, also known as “scrubbers” ) or with dry sorbent injection (DSI). EGUs may choose either “wet” or “ dry” configurations of scrubbers. Wet scrubbers can use a variety of reagents including crushed limestone, quick lime, and magnesium
- enh anced lime. The choice of reagent affects performance, size, capital and operating costs. Current wet scrubber technology is capable of removing at least 99 percent of HF and HCl emissions while simultaneously achieving 96 percent SO 2 removal. Modern dry F GD technology combines lime
- based slurry with a downstream fabric filter to remove at least 93 percent SO 2 while also capturing over 99 percent2
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HCL and HF. An alternative to scrubber technology is dry sorbent injection (DSI), which injects an alkaline powd ered material (post combustion) to react with the acid gases. The product of this reaction is removed by particulate matter (PM) control device. DSI technology is most efficient with a baghouse present downstream but can function with an electrostatic prec ipitator (ESP) downstream as well. Under these circumstances, the ESP requires more reagent per molecule of acid gas removed as compared to a similar operation with a baghouse. Finally, DSI may employ a multitude of sorbents (trona , 2 sodium carbonate, calc ium carbonate
— and their bicarbonate counterparts) for a more tailored approach to reduce emissions based on the source, cost, and unit and fuel characteristics. Mercury capture and removal requires multiple controls. Upon combustion, mercury exits the furn ace in three forms: elemental, oxidized, and as a particulate. Elemental mercury is emitted out of the stack. The particulate form is bound to the ash and removed by PM control equipment such as ESP or fabric filter. A portion of mercury that has converted to oxidized compounds may be removed by either a wet scrubber or by activated carbon injection (ACI). Each of these control devices uses a different method to remove the mercury compounds. The wet FGD system captures oxidized mercury because it is water s oluble, while activated carbon injection provides a unique physical surface to which oxidized mercury can adhere. Mercury oxidation can occur at multiple locations within a unit as long as an oxidizing agent, generally a halogen, is present for reaction. T his allows the unit operator some latitude in selecting a control method and injection point based on existing equipment at the particular source. A halogen can be introduced to the fuel prior to combustion, injected directly into the furnace, introduced u pstream of a selective catalytic reduction (SCR) system , 3 or infused with the activated carbon injections. The unit operator may also increase halogens by blending in higher chlorine fuels (e.g., Powder River Basin fuel blended with bituminous coal). Opera ting a wet FGD for SO 2 control alongside selective catalytic reduction (SCR) for NO x control with sufficient halogen present will remove more than 90 percent of the mercury within the flue gas stream. Alternatively, in the absence of a wet FGD, activated c arbon injection (ACI) can be employed for mercury capture with at least 90 percent removal using a downstream fabric filter. An ESP results in less efficient mercury removal with ACI. Non
- mercury heavy metals and organics are removed by PM control equipmen t such as fabric filters and ESP. Unlike mercury, the heavy metals (e.g., selenium and arsenic) are non
volatile and affix to the ash. Likewise, any organics surviving the high temperature combustion

2 Trona refers to th e chemical compound sodium sesquicarbonate. 3 SCR is primarily used for NO x control, but can also be used to promote mercury oxidation.2
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process are non -volatile and bind to the ash. Both control technologies are capable of removing more than 99 percent of PM 2.5 mass from the emissions stream. ESPs sap relatively little energy from the flue gas but are less flexible for fuel switching, since they are designed for use with a specific intended fue l. Fuel switching or blending that increases gas flow rate, ash resistivity, or particle loading may render an existing ESP insufficient for removing particulate matter. ESPs also suffer from ash re
- entrainment, which is the release of particulate matter f rom the last compartment due to the self cleaning action. On the other hand, an ESP with sufficient design margin may succeed with these fuel alterations. Conversely, a fabric filter does not suffer from these limitations. Moreover, the fabric filter readi ly lends itself to mercury and acid gas removal since DSI and ACI operate more efficiently with a baghouse. When considering retrofit PM control options, a unit with an existing ESP will examine upgrading the precipitator as an alternative to installing a new fabric filter to achieve emission reductions. For more detail on the cost and performance assumptions of pollution controls, see the documentation for the Integrated Planning Model (IPM) , 4 a dynamic linear programming model that EPA uses to examine air pollution control policies for various air emissions throughout the United States for the entire power system. **2.6 HAP Regulation in the Power Sector**  **2.6.1 Programs Targeting HAP**  In 2000, EPA made a finding that it was appropriate and necessary to regula te coal
- and oil
-fired EGUs under CAA section 112 and listed EGUs pursuant to CAA section 112(c). This finding triggered a requirement for EPA to propose regulations to control air toxics emissions, including mercury, from these facilities. On January 30, 2004, EPA proposed a rule with two basic approaches for controlling mercury from power plants. One approach would require power plants to meet emissions standards reflecting the application of the “ maximum achievable control technology” (MACT) determined a ccording to the procedure set forth in section 112(d) of the Clean Air Act. A second approach proposed by EPA would create a market
- based “ cap and trade ” program that, if implemented, would reduce nationwide utility emissions of mercury in two phases under Section 111 or Section 112 of the Clean Air Act. EPA also proposed to revise its December 2000 finding that it is “ appropriate and necessary” to regulate utility hazardous air emissions using the MACT standards provisions (section 112) of the Clean Air Act.

4 Documentation for IPM can be found at www.epa.gov/airmarkets/epa

- ip m .2
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On March 15, 2005, EPA issued the final Clean Air Mercury Rule (CAMR). CAMR established “standards of performance ” limiting mercury emissions from new and existing utilities and created a market
- based cap
- and
-trade program to reduce nationwide utility e missions of mercury in two phases. In conjunction with CAMR, EPA published a final rule (Section 112(n) Revision Rule) that removed EGUs from the list of sources for which regulation under CAA section 112 was required. The Section 112(n) Revision Rule was vacated on February 8, 2008, by the U.S. Court of Appeals for the District of Columbia Circuit. As a result of that vacatur, CAMR was also vacated and EGUs remained on the list of sources that must be regulated under CAA section 112. This action finalizes the rule EPA proposed on March 16, 2011 to replace CAMR in response to the court’ s decisions. **2.6.2 Programs Targeting SO** **2 and NOx**  Programs to reduce SO 2 and NOx also impact emissions of mercury and other HAP. At the federal level, efforts to reduce emi ssions of SO 2 have been occurring since 1970. Policy makers have recognized the need to address these harmful emissions, and incremental steps have been taken to ensure that the country meets air quality standards. The recently finalized Cross State Air Pollution Rule (CSAPR) is the next step toward attainment of the national standards for PM 2.5 and ozone. Even before widespread regulation of SO 2 and NO X for the power sector, total suspended particulate matter (TSP) was a related target of state and fede ral action. Because larger particulates are visible as dark smoke from smokestacks, most states had regulations by 1970 limiting the opacity of emissions. Requirements for taller smokestacks also mitigated local impacts of TSP. Notably, such regulations effectively addressed large
- diameter, filterable particulate matter rather than condensable particulate matter (such as PM 2.5 ) associated with SO 2 and NO X emissions, which are not visible at the smokestack and have impacts far from their sources. Federal regulation of SO 2 and NO X emissions at power plants began with the 1970 Clean Air Act. The Act required the Agency to develop New Source Performance Standards (NSPS) for a number of source categories including coal
-fired power plants. The first NSPS for power plants (subpart D) required new units to limit SO 2 emissions either by using scrubbers or by using low sulfur coal. NO X was required to be limited through the use of low NO X burners. A new NSPS (subpart Da), promulgated in 1978, tightened the stand ards for SO 2, requiring scrubbers on all new units.2
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The 1990 Clean Air Act Amendments (CAAA) placed a number of new requirements on power plants. The Acid Rain Program, established under Title IV of the 1990 CAAA, requires major reductions of SO 2 and NO X emissions. The SO 2 program sets a permanent cap on the total amount of SO 2 that can be emitted by electric power plants in the contiguous United States at about one
- half of the amount of SO 2 these sources emitted in 1980. Using a market
- based cap and tra de mechanism allows flexibility for individual combustion units to select their own methods of compliance with the SO 2 reduction requirements. The program uses a more traditional approach to NO X emissions limitations for certain coal
-fired electric utility boilers, with the objective of achieving a 2 million ton reduction from projected NO X emission levels that would have been emitted in 2000 without implementation of Title IV. The Acid Rain Program comprises two phases for SO 2 and NO X . Phase I applied pr imarily to the largest coal
-fired electric generating sources from 1995 through 1999 for SO 2 and from 1996 through 1999 for NO X . Phase II for both pollutants began in 2000. For SO 2, it applies to thousands of combustion units generating electricity natio nwide; for NO X it generally applies to affected units that burned coal during 1990 through 1995. The Acid Rain Program has led to the installation of a number of scrubbers on existing coal
-fired units as well as significant fuel switching to lower sulfur coals. Under the NO X provisions of Title IV, most existing coal
-fired units installed low NO X burners. The CAAA also placed much greater emphasis on control of NO X to reduce ozone nonattainment. This led to the formation of several regional NO X trading p rograms as well as intrastate NO X trading programs in states such as Texas. The northeastern states of the Ozone Transport Commission (OTC) required existing sources to meet Reasonably Available Control Technology (RACT) limits on NO X in 1995 and in 1999 began an ozone
- season cap and trade program to achieve deeper reductions. In 1998, EPA promulgated regulations (the NO X SIP Call) that required 21 states in the eastern United States and the District of Columbia to reduce NO X emissions that contributed to nonattainment in downwind states using the cap and trade approach. This program began in May of 2003 and has resulted in the installation of significant amounts of selective catalytic reduction. The Clean Air Interstate Rule (CAIR) built on EPA’s efforts in the NO X SIP call to address specifically interstate pollution transport for ozone, and was EPA’s first attempt to address interstate pollution transport for PM 2.5 . It required significant reductions in emissions of SO 2 and NO X in 28 states and the District of Columbia (see Figure 6
-4 below). EGUs were found to be a major source of the SO 2 and NO X emissions which contributed to fine particle concentrations and ozone problems downwind. Although the D.C. Circuit remanded the rule to2
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EPA in 2008, it did so without vacatur, allowing the rule to remain in effect while EPA addresse d the remand. Thus, CAIR continued to help states address ozone and PM 2.5 nonattainment and improve visibility by reducing transported precursors of SO 2 and NO X through the implem entation of three separate cap and trade compliance programs for annual NO X, ozone season NO X, and annual SO 2 emissions from power plants. Perhaps in anticipation of complying with CAIR, especially the more stringent second phase that was set to begin in 2 015, several sources began installing or planning to install advanced controls for SO 2 and NO X to begin operating in the 2010 to 2015 timeframe. Many EPA New Source Review (NSR) settlements also require d controls in those years, as do state rules in Georg ia, Illinois, and Maryland. States like North Carolina, New York, Connecticut, Massachusetts, and Delaware have also moved to control these emiss ions to address nonattainment. On July 6, 2011, the EPA finalized the Cross
- State Air Pollution Rule (CSAPR) to replace CAIR
. T he rule requires states to eliminate the portion of their emissions defined as their “significant contribution” by setting a pollution limit (or budget) for each covered state. The rule allows air
- quality
- assured allowance trading among covered sources, utilizing an allowance market infrastructure based on existing, successful allowance trading programs. The final CSAPR allows sources to trade emissions allowances with other sources within the same program (e.g., ozone season NOx) in th e same or different states, while firmly constraining any emissions shifting that may occur by requiring a strict emission ceiling in each state (the budget plus variability limit). It also includes assurance provisions that ensure each state will make the emission reductions necessary to fulfill the “good neighbor” provision of the Clean Air Act. **2.7 Revenues, Expenses, and Prices**  Due to lower retail electricity sales, total utility operating revenues declined in 2009 to $276 billion from a peak of almost $300 billion in 2008. However, operating expenses were appreciably lower and as a result, net income actually rose modestly compared to 2008 (see Table 2
- 7). Recent economic events have put downward pressure on electricity demand, thus dampening electricity prices and consumption (utility revenues), but have also reduced the price and cost of fossil fuels and other expenses. Electricity sales and revenues associated with the generation, transmission, and distribution of electricity are expected to rebound a nd increase modestly by 2015, where they are projected to be roughly $360 billion (see Table 2
- 8). Based on EIA’ s Annual Energy Outlook 2011, Table 2
- 8 shows that in the base case, the power sector is expected to derive revenues of $360 billion in 2015. Ta ble 2
- 7 shows that2
- 14

investor
- owned utilities (IOUs) earned income of about 11.5% compared to total revenues in 2009. Assuming the same income ratio from IOUs (with no income kept by public power), and using the same proportion of power sales from public pow er as observed in 2009, EPA projects that the power sector will expend over $320 billion in 2015 alone to generate, transmit, and distribute electricity to end
- use consumers. Over the past 50 years, real retail electricity prices have ranged from around 7 cents per kWh in the early 1970s, to around 11 cents, reached in the early 1980s. Generally, retail electricity prices do not change rapidly and do not display the variability of other energy or commodity prices, although the frequency at which these price s change varies across different types of customers. Retail rate regulation has largely insulated consumers from the rising and falling wholesale electricity price signals whose variation in the marketplace on an hourly, daily, and seasonal basis is critic al for driving lowest
- cost matching of supply and demand. In fact, the real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 2
- 3 ).2
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**Table 2 -**  **7. Revenue and Expense Statistics for Major U.S. Investor** **- Owned Electric Uti**  **lities for 2009 ($millions)**  **2008 2009**  **Utility Operating Revenues 298,962**  **276,124** Electric Utility 266,124 249,303 Other Utility 32,838 26,822 **Utility Operating Expenses 267,263**  **244,243** Electric Utility 236,572 219,544 Operation 175,887 154,925 Pro duction 140,974 118,816 Cost of Fuel 47,337 40,242 Purchased Power 84,724 67,630 Other 8,937 10,970 Transmission 6,950 6,742 Distribution 3,997 3,947 Customer Accounts 5,286 5,203 Customer Service 3,567 3,857 Sales 225 178 Administrative and General 14,718 15,991 Maintenance 14,192 14,092 Depreciation 19,049 20,095 Taxes and Other 26,202 29,081 Other Utility 30,692 24,698 **Net Utility Operating Income 31,699**  **31,881** Source: EIA ( 2009 ). Note: Th e s e data do not include information for public util ities. **Table 2 -** **8. Projected Revenues by Service Category in 2015 for Public Power and Investor** ****

**Owned Utilities (billions)** Generation $195 Transmission 36 Distribution 129 **Total $360**  Source: EIA ( 2011 ). Note: Data are derived by taking either total electricity use (for generation) or sales (transmission and distribution) and multiplying by forecasted prices by service category from Table 8 (Electricity Supply, Disposition, Prices, and Emissions).2
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**Figure 2 -**  **3 .**  **National Average Retail Electricity Price (1 960** **– 2009)**  Source: EIA ( 2009 ). On a state
- by
- state basis, retail electricity prices vary considerably. The Northeast and California have average retail prices that can be as much as double those of other states (see Figure 2
-4 ).

**Figure 2 -** **4 .**  **Average Retail Electricity Price by State (cents/kWh), 2009**  Source: EIA ( 2009 ).2
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**2.7.1 Natural Gas Market**  The natural gas market in the United States has historically experienced significant price volatility from year to year, between seasons within a year, and can undergo major price swings during short
- lived weather events (such as cold snaps leading to short
- run spikes in heating demand). Over the last decade, gas prices (both Henry Hub 5 prices and delivered prices to the power sector) have ranged from $3 per mmBtu to as high as $9 on an annual average basis (see Figure 2
- 5 ). During that time, the daily price of natural gas reached as high as $15/mmBtu. Recent forecasts of natural gas have also experienced considerable revision as new sources of gas have been discovered and have come to market, although there continues to be some uncertainty surrounding the precise quantity of the resource base. 6

**Figure 2 -**  **5 .**  **Natural Gas Spot Price, Annual Average (Henry Hub)** Source: EIA ( 2010a ) , EIA ( 2011 ).

5 The Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange. It is a point on the natural gas pipeline system that interconnects nine interstate and four intrastate pipelines. 6 In August, EIA annou nced it would lower its previous estimates of recoverable shale gas by nearly 80 percent. EPA’s modeling of the natural gas market is discussed in more detail in Chapter 7 of this RIA.2
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**2.8 Electricity Demand and D**  **emand Response** Electricity performs a vital and high
-value function in the economy. Historically, growth in electricity consumption has been closely aligned with economic growth. Overall, the U.S. economy has become more efficient over time, producing more output (GDP) per unit of energy input, with per capita energy use fairly constant over the past 30 years. The growth rate of electricity demanded has also been in overall decline for the past sixty years (see Figure 2
- 8), with several key drivers that are worth noting. First, there has been a significant structural shift in the U.S. economy towards less energy
- intensive sectors, like services. Second, companies have strong financial incentives to reduce energy expenditures. Third, companies are responding to the marketplace and continually develop and bring to market new technologies that reduce energy consumption. Fourth, other policies, such as energy efficiency standards at the state and Federal level, have helped address certain market failures. These b roader changes have altered the outlook for future electricity growth (see Figure 2
- 6 ).

**Figure 2 -**  **6 .**  **Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual Energy Outlook 2011**  Source: EIA ( 2009 ) , EIA ( 2011 ).2
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Energy efficiency ini tiatives have become more common, and investments in energy efficiency are projected to continue to increase for the next 5 to 10 years, driven in part by the growing number of states that have adopted energy efficiency resource standards. 7 These investmen ts, and other energy efficiency policies at both the state and federal level, create incentives to reduce energy consumption and peak load. According to EIA, demand
- side management provided actual peak load reductions of 31.7 GW in 2009. For context, the c urrent coal fleet is roughly 320 GW of capacity. Demand for electricity, especially in the short run, is not very sensitive to changes in prices and is considered relatively price inelastic, although some demand reduction does occur in response to price. W ith that in mind, EPA modeling does not typically incorporate a “demand response ” in its electric generation modeling (Chapter 3 ) to the increases in electricity prices typically projected for EPA rulemakings. Electricity demand is considered to be constan t in EPA modeling applications and the reduction in production costs that would result from lower demand is not considered in the primary analytical scenario that is modeled. This leads to some overstatement in the private compliance costs that EPA estimat es. Notably, the “ compliance costs” are the changes in the electric power generation costs in the base case and pollution control options that are evaluated in Chapter 3 . In simple terms, it is the resource costs of what the power industry will directly ex pend to comply with EPA’ s requirements. **2.9 References**  U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2003. 2003. Available online at: http://www.eia.gov/oiaf/archive/aeo03/index.html
. U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2009 . 2009. Available online at: http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.htm l
. U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010 . 2010a. Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html
. U.S. Energy Information Administration (U.S. EIA). “Status of Electricity Restructuring by State. ” 20 10b. Available online at: http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html
. U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011 . 2011. Available online at: http://www.eia.gov/forecasts/aeo/
.

7 To the extent that EIA includes these measures in its baseline foreca st from the Annual Energy Outlook, EPA has also incorporated them into the baseline for purposes of assessing the economic impacts of this rule. See AEO 2011 and Chapter 3 and the IPM documentation for more detail.